Scale and Corrosion

Introduction and the objective of the work package

When the integrity of wells, facilities and pipelines are at risk, the remaining reserves recoverable well may be lost. Deposits of scale, debris, schmoo and corrosion are all contributing factors for potential loss of integrity as well as decreased production potential of the well. Therefore, improved understanding of observed mechanisms and development of testing methods as well as modelling tools for predicting and potentially mitigating scale deposit and corrosion is essential for optimal recovery of the remaining reserves. The aim with this work package is to ensure lifelong integrity of wells, facilities and pipelines. The Gorm asset is chosen as the pilot field in accordance to CTR.2 Demo-model. However, it is expected that the findings will be also used in the Halfdan, Dan and Kraka fields.

The main objective of this work package is to establish a risk based well intervention planning process to ensure optimal recovery of the remaining reserves by improving producer/ injector well availability in terms of both flow rate and commercial life by reducing well maintenance cost. The primary work is focused in solving scale and corrosion challenges in wells, however future research will also concentrate on top side pipes (e.g. flow lines).

Structure of the Work package

The work package is divided into four key areas (Corrosion, Scale, Reservoir Souring and Risk Management) with respective research managers ensuring the alignment of the projects with observed challenges (see Figure 1).

The focus of the work and challenges related to each of the research areas are described in the following sections.

i. Corrosion area

Corrosion is a common problem in the oil and gas industry, which reduces the lifetime of oilfield equipment. An extensive internal corrosion in the e.g. multiphase export pipelines, topside pipes or in the wells often leads to replacement of used materials to corrosion resistant alloys. In the case of wells, workovers are performed, when the well integrity is at risk due to corrosion.

To prevent corrosion, e.g. corrosion inhibitors, H2S and O2 scavengers or biocides can be used. However, despite of using such mitigation techniques, extensive corrosion in wells is still observed.

The conditions present in the wells are complex and the severity of corrosion depends on various environmental (e.g. CO2/H2S/O2, seawater fraction, temperature, pressure, liquid flow velocity, stresses etc.) and material variables (e.g. chemical composition, microstructure, surface roughness). Additionally, the formation of scales (e.g. CaCO3) and the techniques used to remove them (chemical and/or mechanical) might also contribute to increased corrosion rates. Therefore, the corrosion observed in the wells often involves several mechanisms, which makes it difficult to predict and define which of them lead to loss of well integrity. Further, it is also challenging to monitor corrosion processes in the wells especially when the localized corrosion occurs underneath the formed scale.

For that reason, the research in this area is focused on defining corrosion mechanisms and governing parameters responsible for enhanced corrosion rates in the wells. Further, the work is to be concentrated on developing appropriate predictive tolls, appropriate mitigation techniques to minimize the corrosion risk as well as reliable monitoring technologies. This in turn will reduce the operational cost of the oil production as well as decrease the operational risk.

ii.Scale area

The formation of the scale (e.g. CaCO3, BaSO4) in the wells is undesired as scale deposition will increase the surface roughness of the pipe and decrease the flow area, resultantly impacting the efficiency of the well (see example in Figure 2). Moreover, the well integrity may be challenged due to scale precipitation across sub-surface safety valves (SSSV). Further, it is believed that the scale formation increases the risk for under-deposit corrosion and pitting, which may influence the well integrity.

Depending on the physical properties of the scales (e.g. solubility, hardness), either chemical or mechanical methods can be used to remove them. However, such scale-removal techniques are costly and might contribute to increased corrosion rate and shorter lifetime of the wells, facilities and pipelines. Therefore, the focus of this area is to understand the mechanisms and kinetics of scale formation and predict the operating conditions that cause the various types of scales to be formed and where in the well the scales are located. It is believed that such information will help to predict and carefully plan appropriate treatments, which would be either used to mitigate scale formation or to remove already existing deposits. It will in turn result in reduced operating expenditures as well as increased oil recovery and extended lifetime of the wells, facilities and pipelines.

Biological hydrogen sulphide production in oil reservoirs and pipelines is an unfavourable phenomenon as leads to higher operational costs of oil production. The produced hydrogen sulphide is a toxic gas leading to health and safety issues; it also enhances infrastructure corrosion among other negative effects. Souring in such systems is mainly due to respiration of anaerobic microorganisms (sulphate-reducing prokaryotes, SRP) that reduces sulphate to sulphide. These microorganisms may exist indigenously in oil reservoirs or/and may be introduced into the system during drilling and waterflooding. Utilising seawater for waterflooding provides additional sulphate and SRP in the system. It also lowers reservoir temperature providing a favourable condition for SRP activity. The main strategies to reduce the probability of souring are: injecting nitrate and/or nitrite to inhibit SRP activity and/or oxidize sulphide; removing sulphate from injection water; and biocide treatments.

In the Halfdan oilfield, controlling the microbial souring by injecting nitrate to shift the indigenous microbial community away from sulfide production has become an established method. However, to predict and design the cost effective long-term strategies for the souring control process more work is needed.

The reliable quantification of the mechanism of nitrate/nitrite inhibition under altered reservoir conditions is still a challenge and requires more examinations. The effects of induced fractures, reservoir heterogeneity, short circuits between wells, bioavailability, self-inhibition, and altered reservoir temperature on the souring control process have not been studied in detail in the Halfdan oilfield. The focus of this group is on developing detailed reservoir simulations incorporating all the relevant available information (tracer tests, the updated static model, measured nitrate, nitrite, H2S and CO2 concentrations in the wells), which is required to predict the success of various treatment options while reducing the uncertainties.

Offshore structures, pressure vessels, pipelines, wells and process system are designed to assure a certain performance for the different operations during the service life according to given requirements and acceptance criteria, generally related to safety of personnel and environmental and financial risk. In this context, risk management allows to formulate the best strategy aiming at obtaining the desired performance with respect to the acceptance criteria by means of classical decision analysis, where the objective is to minimize the risk function. In general terms, the risk is defined as , where indicates the expected value of the consequences associated to the failure mode and denotes the probability of the failure event . Therefore, the first step into risk management is to identify the system with all its components, functionalities, failure modes and deterioration mechanisms along with inspection techniques and repair techniques.

Depending on local environmental conditions, design criteria and applied protective measurements, sub-surface wells are affected by different deterioration processes (e.g. corrosion and scale) causing progressive loss of integrity and production capability. The different deterioration processes will follow different patterns both in time and space depending on the choice of material, detailing of the completion and processes, operations and exposure to aggressive environment.

Current best practice identifies inspections as effective tool to control the degree of deterioration of the well completion. However, inspections have large impact on the operation of the well and are very costly (e.g. workovers), depending on the accessibility of the components that has to be inspected and therefore they are operated in a corrective framework. In addition, based on the outcome of the inspections, effective corrective repairs need to be identified and planned to assure continuity of operation and low deterioration rate of the well.

In order to maximize the benefit from an inspection, proactive inspection planning is needed, following the criteria of the best balance between the expected benefit of the inspections and the corresponding cost, taking into account that the inspection may lead or not to the choice of a corrective measure (repair). In addition, different inspection strategies (effort, quality, costs), as well as different maintenance techniques, may be available and lead to different effects when evaluating the risk based asset management strategy. By comparing the risk associated with different inspection and maintenance strategies, the asset management strategy implying the lower risk can be identified.

Aim of the risk management activity is the development of probabilistic models for the different degradation processes with the aim to predict the performance of offshore wells and the implementation of the Risk Based Inspection Planning methodology for identifying the best maintenance strategy for subsurface wells and assure operability for an extended lifetime reducing costly workovers.

Danish Hydrocarbon Research and Technology Centre

The Danish Hydrocarbon Research and Technology Centre at DTU is tasked with researching and developing new technologies with a view to improving utilization of the North Sea reserves of oil and gas. The centre is located at DTU and affiliated with research groups at the University of Copenhagen, Aarhus University, Aalborg University, and the Geological Survey of Greenland and Denmark (GEUS).

The Danish Hydrocarbon Research and Technology Centre at DTU is backed by the DUC partners who will award the centre funding in the amount of DKK 1 billion over ten years.